Currently available gasoline contains sulfur contaminants at an average cumulative level exceeding 300 parts per million by weight (ppmw) of sulfur (i.e., calculated based on sulfur weight). On-road application diesel fuel has a higher sulfur content ranging typically from 300 to 2,000 ppmw. Combustion of gasoline and diesel fuels during use in internal combustion engines, in turn, converts the sulfur contaminants into sulfur oxides. The sulfur oxides are environmentally undesirable and also have been found to have a long-term deactivation impact on automotive catalytic converters that are used to remove nitrogen oxide and unburned hydrocarbon contaminants from automotive emissions.
In order to improve air quality, environmental protection agencies of various industrialized countries have therefore announced or proposed new regulations requiring reduction in sulfur content of gasoline, diesel, and other motor fuels. In the United States, the Environmental Protection Agency (EPA) is requiring that the sulfur content of gasolines be reduced to a maximum of 30 ppmw by the year 2005 under recently implemented Tier 2 regulations. Similarly, the EPA has enacted regulations to bring down the sulfur levels in diesel fuel used for on-road application to 15 ppmv or below by 2006. It is anticipated that due to public demand for a cleaner environment, the future will bring calls for even stricter sulfur oxide emissions and fuel specifications; and, as a result, fuels containing nearly zero sulfur levels are being discussed. Accordingly, the new regulations will require sulfur reduction of typically 90% or more by 2005, and perhaps complete sulfur removal thereafter. At the same time, the sulfur content of commercially available crude oils produced in the United States and in neighboring American countries has been generally increasing; thus the new regulations will require more drastic sulfur reduction in the future. Further reductions meeting nearly zero sulfur levels required by expected future regulations will exacerbate this problem further.
Various technologies are currently available or have been proposed which are believed to be capable of reducing sulfur contaminants in gasoline to 30 ppmw or less. According to a recent study conducted by EPA, these available and proposed technologies include hydrotreating and adsorption-based processes (see Regulatory Impact Analysis—Control of Air Pollution From New Motor Vehicles: Tier 2 Motor Vehicle Emissions Standards and Gasoline Sulfur Control Requirements, EPA 420-R-99-023, United States Environmental Protection Agency, December 1999, Chapter IV, pp. IV-42-IV-65).
As detailed in the EPA study, the sulfur content of current gasolines is attributable primarily to fluidized catalytic crackers (FCC), or to coker units, which convert heavy boiling stocks to gasoline components or precursors, i.e., naphthas. It has been reported that more than 90% of the sulfur in gasoline comes from streams produced in the FCC unit. The sulfur content of FCC naphtha varies from 150 to 3,000 ppmw depending upon the sulfur concentration of feed and the endpoint of the gasoline product. Accordingly, reduction of sulfur in motor gasoline can be accomplished by FCC feed hydrotreating or by hydrotreating the naphtha cut obtained from the FCC unit. The latter process is preferred because of substantially lower cost resulting from substantially lower volumes of the feedstocks to be processed.
Nevertheless, hydrotreating of FCC naphtha is expensive, both in capital investment, and in operating costs. In particular, hydrotreating of FCC naphtha is typically carried out in a packed-bed or a fixed-bed reactor using various well-known hydrodesulfurization (HDS) catalysts. These catalysts typically contain a Group 8 (other than iron), 9, or 10 transition metal such as cobalt and/or nickel combined with a Group 6 transition metal, particularly molybdenum or tungsten, on a high surface area alumina support (“Group metal” as used herein is based on the new IUPAC format for the Periodic Table of the Elements, which numbers the groups from 1 to 18 in Arabic numerals). Before their use, these catalysts are typically pre-sulfided under controlled reducing conditions to impart their HDS catalytic activity. Other HDS catalysts include platinum, palladium, or like metals supported on alumina. In the presence of HDS catalysts, organic sulfur compounds present in FCC naphtha react with hydrogen and are converted into hydrogen sulfide at temperature and pressures or 300 to 500° C., and 400 to 600 psig. The hydrogen sulfide thus formed can be subsequently and readily removed in a downstream unit by sorbents or other processes such as a combination of amine and Claus processes.
However, during the HDS hydrotreating process, octane number loss can occur by saturation of high-octane containing olefins that are present in FCC naphtha. Moreover, increased olefin saturation is accompanied by increased hydrogen consumption and cost. In addition, there can be a loss in gasoline yield caused by mild cracking which breaks some of the naphtha into smaller, lighter fractions, which are too light for blending into gasoline.
Three proven hydrotreating desulfurization technologies are identified in the EPA report cited previously. However, octane number loss remains a serious problem with all three proven technologies particularly when applied for removal of 90 percent or more sulfur from the FCC naphtha to meet EPA's Tier 2 requirements.
Newly proposed technologies identified in the EPA report include a catalytic distillation technology, called CDTech, which relies upon an HDS catalyst supported in a distillation column to provide reaction of organic sulfur compounds with diene compounds present in FCC naphtha. The resultant thioether reaction product has a higher boiling point and can be removed from the bottom of the distillation column. Similar to conventional hydrotreating processes, this process also uses an HDS catalyst. However, hydrogen consumption and olefin saturation are claimed to be lower compared to conventional hydrotreating processes. The operating cost for sulfur removal using the CDTech process is reported to be 25% lower than conventional hydrotreating processes for the same degree of sulfur removal.
Two emerging adsorption-based desulfurization processes are also discussed in the EPA report. One process, named IRVAD, adsorbs heteroatom-containing hydrocarbon compounds, including sulfur, nitrogen, and oxygen compounds, present in FCC naphtha onto an alumina-based adsorbent in liquid phase (see U.S. Pat. No. 5,730,860, issued Mar. 24, 1998 to Irvine). The adsorbent is fluidized in a tall column and continuously removed and regenerated using hydrogen in a second column. The regenerated catalyst is then recycled back into the reactor. The regeneration of spent adsorbent produces a hydrocarbon stream containing about 1 wt % sulfur, which can be treated using conventional processes. While the inventors have claimed an overall cost of sulfur removal as low as 0.77 cents per gallon of gasoline compared to 5 to 8 cents for conventional hydrotreating processes, serious process and system integration issues still remain with this technology, which are hampering its commercial deployment.
The other emerging adsorption-based desulfurization technology named as the SZorb process is being developed by the Phillips Petroleum Company. It is understood that this process uses an adsorbent/catalyst comprising one or more metallic promoters, such as a combination of nickel and cobalt, in a zero valence state to selectively remove sulfur compounds from FCC naphtha in the presence of hydrogen. As the adsorbent/catalyst becomes saturated with sulfur compounds, it is sent to a regeneration unit where it is treated with an oxygen-containing gas for removal of the sulfur as sulfur dioxide. The oxidized adsorbent/catalyst is further treated with hydrogen in a downstream reducing unit presumably to reduce some of the metal oxide/s present in the adsorbent/catalyst composition to their reduced forms. The reduced adsorbent/catalyst is then fed to the sulfur removal unit, along with hydrogen, for further desulfurization of FCC naphtha. This process is carried out at a temperature between about 250 to about 350° C. (about 500 to about 700° F.) and a pressure of 100 to 300 psig. Phillips proposes to use conventional bubbling-bed fluidized-beds for adsorption and regeneration reactors, which will have inherent limitation on throughput of the FCC naphtha feed that can be processed in this system. Phillips claims that this process can remove about 97% of the sulfur from FCC naphtha with a 1 to 1.5 point loss in octane number and with an operating cost of 1.5 to 2 cents per gallon of gasoline. However, the need for a two-step regeneration process, consumption of hydrogen and associated octane number loss, and the use of low throughput bubbling-bed systems are some of the major drawbacks of this technology. Recent information from Phillips indicates that this process is being adapted for desulfurization of diesel.
Various other desulfurization processes are known or have been proposed. For example, U.S. Pat. No. 3,063,936, issued on Nov. 13, 1962 to Pearce et al. discloses that sulfur reduction can be achieved for straight-run naphtha feedstocks from 357 ppmw to 10-26 ppmw levels by hydrotreating at 380° C. using an alumina-supported cobalt molybdate catalyst. According to Pearce et al., a similar degree of desulfurization may be achieved by passing the straight-run naphtha with or without hydrogen, over a contact material comprising zinc oxide, manganese oxide, or iron oxide at 350 to 450° C. Pearce et al. propose to increase sulfur removal by treating the straight run naphtha feeds in a three-stage process in which the hydrocarbon oil is treated with sulfuric acid in the first step, a hydrotreating process employing an alumina-supported cobalt molybdate catalyst is used in the second step, and an adsorption process, preferably using zinc oxide is used for removal of hydrogen sulfide formed in the hydrotreating step as the third step. The process is said to be suitable only for treating feedstocks that are substantially free from ethylenically or acetylenically unsaturated compounds. In particular, Pearce et al. disclose that the process is not suitable for treating feedstocks, such as hydrocarbons obtained as a result of thermal cracking processes that contain substantial amounts of ethylenically or acetylenically unsaturated compounds such as full-range FCC naphtha, which contains about 30% olefins.
U.S. Pat. No. 5,157,201 discloses that organic sulfur species, primarily comprising organic sulfides, disulfides, and mercaptans, can be adsorbed from olefin streams, without saturating the olefins, by contacting the feed with a metal oxide adsorbent at relatively low temperatures (50 to 75° C.), in the absence of hydrogen. The metal oxide adsorbent includes metal oxides selected from a group consisting of a mixture of cobalt and molybdenum oxides, a mixture of nickel and molybdenum oxides and nickel oxide supported on an inert support. The adsorbed organic sulfur compounds are removed from the sorbent by purging with an inert gas while heating at a temperature of about 200° C. for at least about 45 minutes. Although such low-temperature adsorption processes avoid any olefin saturation, these processes are limited to removal of lighter sulfur compounds such as mercaptans and organic sulfides and disulfides. These processes cannot be used effectively for removal of thiophenes, benzothiophenes, and higher cyclic sulfur compounds, which typically account for greater than 50% of the sulfur in FCC naphtha.
In summary, currently available and proposed technologies for reducing sulfur content of FCC naphtha feedstocks to levels of 30 ppmw or less are capital intensive, operationally complex, typically require significant hydrogen consumption, can severely reduce octane number values and/or result in loss in yield, and rely on expensive hydrotreating catalysts in whole or in part. In addition, the existing and proposed technologies rely on fixed-bed or bubbling-bed reactors resulting in limited throughputs and substantial capital investment.